Browsing the SGEIS category...

Deputy Commissioner Leff takes the position that the best way to proceed with HVHF in New York State is to make a firm commitment to minimizing all exposures to harmful chemical substances released into
the environment by shale gas exploitation.  I argued that considering the history of shale gas exploitation throughout the United States and the limited ability of the DEC to enforce laws and regulations already in existence it would not be possible for DEC to act in a sufficiently substantial manner upon any commitment to minimization of exposures. There are many pollutant carcinogen exposures associated with shale
gas exploitation that have not been addressed in those areas where this activity exists, including:  (1) benzene, formaldehyde, polycyclic aromatic hydrocarbons (PAHs) and soot particulates emissions of diesel trucks and compressors; (2) chemical carcinogens present in fracturing fluid and disposed of so as to contaminate surface and ground waters; (3) chemical carcinogens evaporating into the outdoor atmosphere from holding tanks utilized at gas well sites; (4) chemical carcinogens evaporating from HVHF waste water and entering the outdoor atmosphere; and (5) radioactive nuclides brought to the surface of the Earth in HVHF waste water.

Shale gas exploitation is not currently possible without imposing a relatively large quantity of exposure to pollutant carcinogens upon New York State residents.  At a time when cancer incidence is already far above an acceptable level as a result of exposures to pollutant carcinogens released into the environment by past and current polluting activities, shale gas exploitation is not acceptable.  Our organization advocates for a ban on shale gas exploitation throughout the United States.

Please utilize the powers of the DEC to set about insuring that the public is provided with a scientific knowledge based portrayal of shale gas exploitation impacts on health.  Will the DEC work in concert with the New York State Department of Health to produce a Health Impact Assessment for shale gas exploitation?  Provision of such a document to the residents of New York State will build political support for the banning of shale gas exploitation in our state.  Knowledge must be used to protect public health.  We find ourselves living in a time of pollutant carcinogen exposure cancer epidemic.  This is the time for minimizing exposure to all pollutant carcinogens.  Please assist with the effort to reject shale gas exploitation in New York State.

Donald L. Hassig, Director
Cancer Action NY
Cancer Action News Network
P O Box 340
Colton, NY USA 13625

In its Executive Summary of the revised SGEIS released yesterday, the DEC states clearly that groundwater is at sufficient risk from gas drilling to restrict gas drilling to protect  those drinking groundwater. But they only afford that protection to those drinking from primary aquifers. The DEC leaves the great majority of drinkers of groundwater in the Marcellus unprotected. They have some explaining to do.

I’m looking forward to hearing the DEC’s logic and science—their risk assessment strategy— used to assess that only some drinkers of contaminated groundwater need protection.

Primary aquifers are used as drinking water for some municipalities.

The list is on  on page 5:

The list includes about 300,000 people in those municipalities drinking water from these primary aquifers in counties in the Marcellus shale. (see attached spreadsheet and chart at bottom.)

Page 18 of the new DEC doc describes the exclusion of primary aquifers. It’s pasted below, bold face added.

No HVHF Operations on Primary Aquifers

Although not subject to Filtration Avoidance Determinations, 18 other aquifers in the State of New York have been identified by the New York State Department of Health as highly productive aquifers presently utilized as sources of water supply by major municipal water supply systems and are designated as “primary aquifers.” Because these aquifers are the primary source of drinking water for many public drinking water supplies, the Department recommends in this dSGEIS that site disturbance relating to HVHF operations should not be permitted there either or in a protective 500-foot buffer area around them. Horizontal extraction of gas resources underneath Primary Aquifers from well pads located outside this area would not significantly impact this valuable water resource.

As the DEC says, this is in addition to the exclusion of drilling in the watersheds of NYC and Syracuse.

Now, one can make an argument, as the DEC has, that the exclusion of drilling in the NYC and Syracuse water supplies is based on their being unfiltered surface water (as opposed to ground  water), with a risk of “turbidity” from surface drilling activity.  And because there have been rules in place for years restricting industry and development  in unfiltered surface watersheds to avoid having to build  super-expensive filtration plants, as  for NYC.  A more clear eyed assessment of carving out the NYC watershed is that the DEC wants to excise the political opposition of NYC, which could easily create a critical mass of opposition in the state.  But they do have the surface water “turbidity” argument  to fall back on to explain this preferential exclusion, even if politics is the underlying reason.

But when you are dealing with groundwater sources, how can you rationally and scientifically exclude some aquifers and not others? Again, the actual rationale appears overtly political, rather than based on the science or risk.  The DEC is trying to carve out the opposition of the  municipalities drinking from primary aquifers—including Jamestown, Elmira, Cortland, Binghamton, Corning, Salamanca.  After all, these municipalities  are really organized entities of people…….. who would otherwise likely oppose drilling.

Problem is, there are at least 1,140,000 people drinking groundwater in the Marcellus shale.   What’s up, DEC? You’ve determined that groundwater is at risk. You’re going to protect 300,000 people from ground water pollution, but not the other 840,000.

Who are those people? Hello, it’s us, the people of rural NY State who will be drinking from polluted wells. It’s us,  people who will not be receiving equal protection against the very threats that the DEC assesses are too risky for the people of upstate municipalities.

I think I’m going to call my lawyer.

Ken Jaffe, MD
Slope Farms
Meredith, NY

county percent of population drinking groundwater county population population drinking groundwater population drinking groundwater from primary aquifer population drinking groundwater not from primary aquifer name of primary aquifer
Cortland 100 49,336 49,336 39,000 10,336 Cortland-
Chenango 95 50,477 47,953 47,953
Tioga 90 51,125 46,013 46,013 Waverly-
Cattaraugus 90 80,317 72,285 72,285 Salamanca
Allegany 85 48,946 41,604 41,604
Steuben 80 98,990 79,192 49,000 30,192 Corning-Cohocton
Broome 80 200,600 160,480 110,000 50,480 Endicott-
Schuyler 80 18,343 14,674 14,674
Madison 75 73,442 55,082 55,082
Otsego 75 62,259 46,694 46,694
Chemung 70 88,830 62,181 50,000 12,181 Elmira
Yates 60 25,348 15,209 15,209
Genesee 60 60,079 36,047 36,047
Wyoming 55 42,155 23,185 23,185
Chautauqua 50 134,905 67,453 52,000 15,453 Jamestown
Seneca 30 35,251 10,575 10,575
Ontario 25 107,931 26,983 26,983
Cayuga 25 80,026 20,007 20,007
Albany 20 304,204 60,841 60,841
Tompkins 15 101,564 15,235 15,235
Onondaga 15 467,026 70,054 70,054
Monroe 10 744,344 74,434 74,434
Erie 5 919,040 45,952 45,952
Totals 3,844,538 1,141,468 300,000 841,468

Source material

  • incomplete DEC data on primary aquifer in Cattaraugus and Tioga Counties may underestimate those drinking from primary aquifer by up to 50,000; this could raise the total using primary aquifers to about 350,000
  • incomplete DEC data on total users of ground water does not include Delaware and Sullivan Counties; this could raise the total users of unprotected groundwater to about 950,000

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By Brian Brock

Programs for oil and gas regulation by the New York State Department of Environmental Conservation were reviewed by Interstate Oil & Gas Compact Commission in 1994.  The resulting fifty five page report examines the details, but does not provide an overview.  Nevertheless Finding I.10 is a good summary: “DMN can not meet its program responsibilities and administer an effective program under current budgetary conditions.  The program is at a crossroads in this regard, because the status quo is not a tolerable long-term condition.”  The Division of Mineral Resources (DMN) is the principle division in charge of oil and gas regulation.

This review was conducted by a team of six experts from IOGCC, state governments, industry, and an environmental group with observers from the federal government, industry, and another environmental group.  First, DEC answered an extensive questionnaire.  Next, DEC staff were interviewed in Saratoga Springs NY May 1 to 5.  The review team met July 13 to 15 to discuss and prepare the draft report, which was then sent to all involved.  The team met a final time August 29 to September 1 to consider all comments and prepare the final report.  Funding was from the federal Environmental Protection Agency.  The full report, minus some of the appendices, is available at

From this final report “New York State Review, IOGCC/EPA State Review of Oil and Gas Exploration and Production Waste Management Regulatory Programs, September 1994”:

Rules and Regulations

“DMN’s regulations … largely originated in 1972.  In the mid-1980s, DMN began a process to substantially upgrade its regulations through … the GEIS in July1992.  Despite the substantial period of time that has expired since the inception of this effort, revised rules have not been proposed or promulgated to date.” {Page 5}  No rules and regulations have been promulgated since.  What is more, the recent draft SGEIS was likewise issued without a rules package.

“In absence of upgraded rules [and regulations], DMN relies substantially upon conditions attached to drilling permits to implement new technical guidance. … Such permit conditions only apply to new wells and therefore of limited utility.  Enforcement questions may also arise from imposing generally applicable permit conditions without first issuing rules supporting those permitting conditions.” {Pages 5 to 6}

“One of the principal stated missions of the DEC is protection of human health and the environment.  However Part 550 [to 559] of DMN’s rules do not expressly include protection of human health and environment as a goal or policy directive.” {Page 6}

“DMN regulations were not in conformance with Article 23 statutes after 1981 [revisions] and were changed as emergency in 1992.” {Appendix B, page 6}


“From a peak staff level of 52 in the mid-1980s, the number of positions declined to 44 in FY 90[-91], and still further to 33 in the last two fiscal years.  Equally important, non-personal funds for purchase of equipment, computers, gasoline, and supplies were dramatically reduced from $230,850 in FY 90-91 to approximately $76,000 in each of the last two fiscal years.” {Page 12}

“Consequently, six inspector positions [including one filled by an inspector on extended leave] are available statewide to inspect [500 to 600 annually of the] 14,000 active wells and 5,000 wells of unknown status.” {Page 38}  Also an estimated 45,000 inactive wells.  In 2008, DMN reported inspection of 2,445 sites annually with a staff of 19.  The 2009 annual report has yet to be released.

“[Staff for] both regions [8 and 9] are under milage and overtime limitations, and have not been able to replace vehicles or purchase other equipment in the past five years.” {Page 38}

“… field staff indicated that they generally operate in a reactive mode due to staff limitations.  For example, they have not conducted routine inspections in the last three years.” {Page 38}

“Additionally inspections such as well plugging, permit transfer, and temporary abandonment inspections are done as resources are available.  Many of the 25 gas storage fields have not been inspected over the last 15 years.” {Page 38}

“The legal side of DMN activities suffers from similar resource deficiencies.  There is currently one program attorney in headquarters, whose responsibilities are divided between oil/gas and mining activities.  While DEC regional attorneys assist DMN regional staff in enforcement matters, this assistance is not always timely or adequate because of competing demands on these DEC attorneys.” {Page 14}

Siting and Permitting

“DMN rules contain several siting provisions, but these provisions apply to wells and not pits or tanks associated the wells.” {Page 21}

“DMN rules related to siting are not comprehensive, since they do not cover areas such as floodplains, wetlands, proximity to drinking water supplies, and depth to groundwater.” {Page 21}

“Fencing flagging, and caging requirements are instituted on a case-by-case basis and are not contained in regulation or guidance documents” {Page 31}

“DMN does not consider operator compliance history when issuing permits.” {Page 17}

“DMN does not provide notice of intention to issues drilling permits and does not allow public comment on drilling permits prior to issuance unless an EIS or other supplementary SEQR document is deemed necessary.” {Page 24}  Since the release of the GEIS in 1992, no permit has required EIS or other supplementary SEQR documents.

“Permits are usually issued within 10-14 days of application” {Page 17}

Brine Wastes

“This [1987] survey indicated 8.6 million barrels [360 million gallons] of produced water were generated that year.  Most produced water is discharged into streams, discharged to land surfaces, or roadspread for ice and dust control [85 to 90 percent] or recycled for water flooding [or commercially treated, 10 to 15 percent].” {Page 9}  Percentages are from Appendix B, page 7.

“In Region 9, according to DMN, there is also a large but unknown number of discharges of produced water directly to land (where there is no pit at the end of the pipe).” {Page 10}

“DMN investigation activities to date have not included abandoned pits and other waste management units.” {Page 44}

“There is no explicit authority in DMN’s rules to require corrective action for non-oil releases.”  {Page 27}  Releases such as brine and gas.

“There is little or no coordination between DRA, DMN, DOW, and local governments regarding the determination of appropriate controls for roadspreading, the monitoring of environmental impacts, or sharing of information on this practice.” {Page 11}  DRA is the Division of Regulatory Affairs, and DOW is Division of Water.

Other Wastes

“DMN’s programs do not require representative testing of drilling cuttings disposed on site, produced brines which are roadspread, or associated wastes.” {Page 29}  Associated wastes include stimulating fluids, completion fluids, produced sands, and drying and sweetening chemicals.

“In short, no agency within the DEC is responsible for, or can produce, reliable information on associated wastes generation or disposal.” {Page 9}

“According to DMN, 90% of drilling solids are buried on-site, and 10% are recycled off-site.”  {Page 9}

“E&P [exploration and production] waste is regulated by DSW as a municipal waste since it is specifically excluded from the definition of industrial waste.” {Page 19} DSW is Division of Solid Waste.

Orphaned Wells

“Almost 18,000 of the 30,000 wells in the database are not plugged according to DMN records.  [Of these 18,000,] the agency has received reports from operators on 12,857 active wells, leaving approximately 5,000 wells of unknown status requiring further investigation.” {Page 42}

“Five thousand three hundred twenty-two unplugged wells of record drilled before 1973 are grandfathered [ie exempted] from financial assurance requirements. … [therefore] DMN holds approximately $12 million of financial assurance to cover a potential liability of $100 million.” {Page 19} Assumes that plugging a well will cost an average of $20,000.

While a few of these deficiencies are addressed in the dSGEIS, those changes would only apply to horizontally drilled shale gas wells.

Changes to the DEC programs since the summer of 1994 have not been documented.  The DEC has not cooperated in a follow-up review to evaluate its progress in the last 17 years.  In 2006, follow-up reviews for New York and Kentucky were scheduled, but the one for New York never took place.  (In contrast, Pennsylvania DEP had its review in 1992, two follow-up reviews in 1997 and 2004, and a review of its hydraulic fracturing program in 2010.)  In response to a 2009 survey, DEC claimed that of the 37 deficiencies cited in the 1994 report, they had fully remedied 10 (27%) and partially remedied 14 (38%), but no documentation was provided.

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Cartoon courtesy of MARQUIL at



From the Desk of Senator Tom Libous
April 27, 2010

Dear ———-,

DEC announced last week that permit applications in the Syracuse and New York City watersheds will be excluded from their environmental review process. All applications for horizontal drilling in these watersheds would need to be reviewed on a case by case basis.

You can read DEC’s full announcement by clicking here.

What does that mean to us? With Syracuse and NYC watersheds having extra protection, this could do two things:

1) Help stop some of the New York City opposition to drilling.

2) Free up DEC’s review efforts to focus on permit applications outside of those areas.

We might see safe gas drilling begin sooner than we thought.

But, we still face opposition from New York City Assembly Speaker Sheldon Silver. You can read his statement on We have to keep fighting.

Best wishes,



Sounds familiar, doesn’t it? : Two maps, two standards, part 2

Then again, maybe he reads our blog…


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November 7, 2008

Bureau of Oil & Gas Regulation
NYSDEC Division of Mineral Resources
625 Broadway, Third Floor
Albany, NY  12233-6500
Attention:  dsGEIS Scope Comments

Dear NYSDEC regulators,
I am a small landowner who is concerned that proposed gas drilling on the two large farms adjacent to my property could contaminate my water well or deplete the aquifer that supplies my well.  I plan on selling my home in the near future and need the monetary gains as part of my retirement income. My home & property value would be rendered virtually worthless if there were no water supply.  I have read the dsGEIS and feel the following items need more emphasis/study or inclusion:

Procurement of professionally trained Gas Drilling Inspectors
Requiring Gas Drilling Companies to prepare Plans and Specifications for submittal to DEC
DEC needs to thoroughly research current gas well casing cement compositions and procedures
DEC should require a gas drilling company to furnish proof of adequate liability insurance

I worked for NYSDOT for 8yrs in the Bridge Design Unit and ODOT (Oregon DOT) for 16 yrs as a Construction Inspector and Materials Tester and later on advanced to an Associate Transportation Engineer as a Roadway Designer.  I will tell you from first hand experience that a project as simple as State Highway Asphalt Paving required an ON-SITE-DAILY- OREGON  D.O.T. TRAINED FIELD INSPECTOR and an ON-SITE-DAILY ODOT ASPHALT MATERIALS INSPECTOR testing the asphalt for such things as moisture content, percentage of asphalt in the mix, aggregate gradation sieve analysis and density.  I know this because I was this Asphalt Materials Inspector.  Thus, an operation the magnitude of the Gas Drilling Operations certainly demands the same attention!!  I stated this at the DEC meeting held in Greene and also the Coalition meeting held in Harpursville.  I also backed my concerns up with two letters to Judith Enck with a copies sent to Assemblyman Clifford Crouch asking both of them to make sure my concerns were carried to the governor prior to him signing the Bill.  I also sent an extremely detailed position description for a Canadian Oil & Gas Drilling Inspector in British Columbia, Canada.  The job description serves to illustrate the importance the Canadian government places on FIELD INSPECTIONS, and the degree of detail contained in the job description shows that gas drilling is not a simple process nor should it be treated as such!  I am extremely grateful to Gov. Paterson and his close advisors for realizing the critical need for Gas Drilling Inspectors and imposing a moratorium on all gas drilling until the state can provide a means of enforcing gas regulations.  But, recognizing the need for inspectors and finding the funding for these positions are two different things especially with the current economy.  Thus, if DEC can not currently fund inspector positions, the gas drilling should only advance as fast as the current DEC inspectors can monitor them!!

Issue 2:  Need for CONTRACT PLANS AND SPECIFICATIONS prepared by the Gas Drilling Companies themselves with submittal to the DEC for review and approval.
I attended a meeting at the Binghamton Public Library conducted by The Independent Oil & Gas Association.  I expressed the need for contract plans/specs and John Holko insisted that the Gas Drillers already provide such plans to the DEC.  The next day, I called Linda Collart of the DEC and conveyed what Mr. Holko had said.  The only thing she knew of that would be a detailed drawing of any sort consisted of ONE SHEET!  I asked her to send me a copy of one of these sheets for a recent DEC approved gas well.  This sheet shows the geological strata, depths, hole & casing design, etc.  But, this one sheet is a far-far-cry from what I am referring to and accustomed to seeing on a Dept. of Transportation project.

During my tenure with NYSDOT and ODOT, I was involved in preparing Preliminary Bridge Plans and specs for interstate bridges on 110 miles of I-88.  I also prepared Preliminary Plans for many Oregon Highway Construction projects from projects as simple as asphalt resurfacing projects all the way up to a modernization project involving widening a two lane highway to four lanes and the creation of a new alignment to meet 70mph design speeds which would avoid impacting 100yr old oak trees, four historic homes, a high power transmission line, and wetland areas.  These plans were extensive in nature, covering every known aspect of the construction and typically entailing 50 or more contract sheets with accompanying specifications of 100 or more sheets.  Thus, I don’t see a Gas Drilling Project as requiring anything less since the impacts can be every bit as far reaching.

To further drive this point home I will explain a project that I have first hand knowledge of  that was in the hands of our very own New York State DEC for review.  These were Contract Plans (24” x 36” size) drawn up by Keystone Engineers for a large pond my neighbor, located on the hill directly above me, was proposing to build.  I became very concerned with the location of this proposed pond and the fact that no one was going to be on site as an inspector to ensure adherence to the specifications.  Thus, I was successful in having DEC deny the permit for this pond.  But the main reason I bring this up is to illustrate that the division of DEC requires rather extensive PLANS and SPECS for a pond when it reaches a certain size and volume.  And I might add that a pond does not pose any risk to underground water tables nor does it contain any toxic chemicals to pollute water supplies!!  Thus, why isn’t this requirement for plans and specs carried over to the Gas Drilling Operations??  The Plans and Specs would succeed in one huge accomplishment, that being —  there would be no mystery and no doubt about what the Gas Companies might be up to; their procedures would have to be clearly explained with accompanying detailed drawings and construction notes showing every aspect of their operation.  It would be very refreshing and assuring for landowners and DEC personnel to know exactly what the Gas Drilling Plan is.

You might be thinking, what is there about a Gas Drilling Operation that would require a detailed drawing plan with accompanying specifications? ….. I will give you just one example:  Environmentalist Bob Williams gave a presentation at the Coalition meeting in Harpursville wherein he showed a picture of a gas drilling pad.  The pad was quite large and required that the earth be leveled with a berm constructed around the perimeter.  This picture caused me to immediately think of my neighbors Pond Plans and Specs.  The gas drilling berm is very much like the pond berm.  The pond berm specs state that “the embankment is to be constructed in maximum 8” thick layers running continuous for the entire length of the fill with each layer being compacted prior to placement of the next layer, and the fill is to have at least 30% passing the #200 sieve.”  Now, do you actually think the drilling pad berm was constructed in this manner??  I would bet the drill pad berm was constructed by a dozer pushin’ dirt up into an unkempt pile that was never even compacted.  Now, what was the pond berm serving to contain?  Yep, pure water.  Now what is the drill pad berm supposed to contain?  You got it, impure hazardous materials!!  As you already know, the Gas Companies are not required to disclose these hazardous materials.  However, Colorado Environmentalist Theo Colburn, PhD has discovered over 200 chemicals directly injected into the gas well during the fracturing process yet she (and I quote) “had been unable to find any information on the chemical content of waste pits until we were sent results of a chemical analysis of the residues from six waste pits in New Mexico.  The 51 chemicals that were detected in those pits produced a health pattern even more toxic than anything we found in the past.  Most important is that 43 of the 51 chemicals detected in the pits were not even on our original list of chemicals used during natural gas operations!”  Thus, this drill pad and waste pits need the same careful plan drawings and specifications as DEC requires for a fairly innocuous pond berm!!  And this is just one example of drilling details that need to be spelled out in a drawing with construction notes/specs. I know you are thinking how requiring the gas companies to develop and submit plans would slow up the gas drilling process even more than the procurement of inspectors, but this could be a good thing.  It could give the state more time to ascertain how it will obtain funding for inspector type staff.  And most of the onus of time and money to develop the plans would be placed on the Gas Drilling Companies with our DEC merely reviewing the plans which takes far less time than developing the plans.


In the above mentioned example of a current DEC approved gas well that Linda Collart sent me, I noticed that Class A cement was being used.  I called her to ask if this was regular Portland Cement and she said yes.  Since I used to be an Asphalt and Concrete Materials Tester for Oregon DOT, I became concerned over the rigidity of Portland Cement and the extreme conditions deep gas well bore holes and drilling operations would exert on this concrete after the casing was cemented.  Thus, I researched this topic and present the following findings:

Proper cementing is critical for the protection of subsurface aquifers and the prevention of gas leaking into zones that would otherwise not be gas bearing.  Tubing and casing leaks, poor drilling and displacement practices, improper cement selection and design, and production cycling may all be factors in the development of gas leaks.  Thus, the primary Gas drilling contractor frequently subcontracts this aspect of gas drilling to a company that exclusively performs this cementing operation. DEC personnel may have heard of “Schlumberger” since they are internationally renowned experts in this field.  I contacted them for help via email and they responded by saying “IF the DEC is interested in soliciting our help we would be willing to participate.”  (I have enclosed a copy of this email.)  Here are some of my findings on this complicated aspect of drilling that even the professionals in the Oil & Gas Industry admit that they are still in the process of perfecting.  Schlumberger says “much work remains to be done in simulating downhole conditions and developing new cement technologies/compositions for thermal applications and high pressure conditions.”

“During the life of a well, the cement sheath may be exposed to stresses imposed by well operations including perforating, hydraulic fracturing, high temperature-pressure differentials, and so on.  Further, if the well is completed using complex completion such as a multilateral system, the cement sheath may be subject to shattering and subsequent loss of bond to pipe impact.  Conventional well cement compositions are typically brittle when cured.  These conventional cement compositions often fail due to stresses, such as radial and/or tangential stresses, that are exerted on the set cement.  In other cases, cements placed in wellbores may be subjected to mechanical stress induced by vibrations resulting from operations, for example, in which wireline and pipe conveyed assembly are moved within the wellbore.  Hydraulic, thermal and mechanical stresses may be induced from forces and changes in forces existing outside the cement sheath surrounding a pipe string.  For example, overburden and geological formation pressures, formation temperatures, formation shifting, formation compaction, etc. may cause stress on cement within the wellbore.  Conventional wellbore cements typically react to excessive stress by failing.”

Halliburton offers the following:  “Wellbores exist in extremely dynamic environments; therefore, a cement sheath must be able to perform as intended over time. When cementing a well, the primary concern is to prevent fluids from migrating into an annulus.  As a well ages, the annular seal may be compromised as a result of stresses brought on by temperature and pressure cycling that occur as the well is operated.  By industry convention and tradition the effect of stresses on the cement sheath’s mechanical properties are not ordinarily assessed during the design and construction phase of a well.  Although short term considerations are necessary for effective slurry mixing and placement, a sole focus on liquid cement slurry properties and the 24 hour compressive strength does not account for long-term cement integrity, which is critical if the well is subjected to stress on a large scale.”  Halliburton has devised an analytical tool, “Welllife” computer software which analyzes properties such as Young’s modulus, friction angle, cohesion of cement sheath and simulates failure events that could occur during various field operations to determine the best cements for particular geological stratum.

Schlumberger says “cement sheath damage or debonding can allow gas to migrate to the surface and cause sustained casing pressure (SCP).  The presence of such flows can require a well to be shut in for remediation or abandoned altogether.”  Schlumberger has designed a “FUTUR active set-cement” which provides long-term zonal isolation and prevents the flow of hydrocarbons through potential leak paths up and along the annulus.  Any hydrocarbon that comes in contact with FUTUR active cement technology will activate the self-healing properties of this unique sealant material.  Once activated, cracks in the cement sheath are healed.  Even if the cement sheath is damaged again, FUTUR active set-cement will continue to self-repair on multiple, independent occasions.

Schlumberger also mentions how important it is to have a clean wellbore prior to cementing.  “It is important to get the initial cementing job right, with good mud removal.  Mud pockets in the annulus can cause catastrophic failure, including broken wellbores and collapsed casing.  Shlumberger uses WELLCLEAN methodology to ensure that there are no channels or pockets of mud that can cause well failure.  Soft formations offer little constraining pressure, and tensile pressures may lead to breakage.  Cements with a low Young’s modulus, such as the flexible cement system using FlexSTONE technology, can deliver mechanical properties appropriate for these downhole stress environments.

The following are excerpts from a paper titled “From Mud to Cement-Building Gas Wells” dated Autumn 2003 by Tom Griffin of Griffin Cementing Consulting LLC, Joseph R. Levine of the US Minerals Management Service, Dominic Murphy of BHP Billiton Petroleum to name but a few of the authors.  This study serves to illustrate the complexity of the cementing process; if the experts in this field attest to the complexity of this aspect of drilling, I think NYSDEC should pay more attention to cement designs and cementing procedures.  “Since the earliest gas wells, uncontrolled migration of hydrocarbons to the surface has challenged the oil and gas industry.  Gas migration, also called annular flow, can lead to sustained casing pressure (SCP), sometimes called sustained annular pressure (SAP).”  “In the Gulf of Mexico, there are approximately 15,500 producing, shut-in and temporarily abandoned wells in the outer continental shelf area.  United States Minerals Management (MMS) data show that 6692 of these wells, or 43%, have reported SCP on at least one casing annulus.”  “By the time a well is 15 years old, there is a 50% probability that it will have measurable SCP in one or more of its casing annuli.  However, SCP may be present in wells of any age.  In Canada, SCP occurs in all types of wells-shallow gas wells in southern Alberta, heavy-oil producers in eastern Alberta and deep gas wells in the foothills of the Rocky Mountains.  Most of the pressure buildup is due to gas.” “Long-term, durable zonal isolation is key to minimizing problems associated with annular gas flow and SCP development.”  “Determining the precise source of annular flow or sustained casing pressure is often difficult, although likely causes can be divided into four primary categories: tubing and casing leaks, poor mud displacement, improper cement-slurry design, and damage to primary cement after setting.  Leaks can result from poor thread connection, corrosion, thermal stress cracking or mechanical rupture of the inner string, or from a packer leak.  If the pressure from a leak causes a failure of the production casing the outcome can be catastrophic.  Leaks to the surface or underground blowouts may jeopardize personnel safety, production-platform facilities and the environment.”  “Inadequate removal of mud or spacer fluids from the borehole prior to cement placement is a major contributing factor to poor zonal isolation and gas migration.” “Improper cement-slurry designs –Flow occurring before cement has set is a result of loss in hydrostatic pressure to the point that the well is no longer overbalanced – hydrostatic pressure is less than formation pressure.  This decrease in hydrostatic pressure results from several phenomena that occur as part of the cement-setting process.  The change from a highly fluid, pumpable slurry to a set, rock-like material involves a gradual transition of the cement.  This may require several hours, depending on the temperature, and quantity and characteristics of retarding compounds added.  As the cement begins to gel, bonding between the cement, casing and borehole allows the slurry to become partially self-supporting.  This self-supporting condition would not be a problem if it occurred alone.  The difficulty arises because, while the cement becomes self-supporting, it loses volume as a result of at least two factors.  First, where the formation is permeable, the hydrostatic pressure overbalance drives water from the cement into the formation.  The rate of water loss depends on the pressure differential, formation permeability, and fluid loss characteristics of the cement.  A second cause pf volume loss is hydration volume reduction as the cement sets.  This occurs because set cement is denser and occupies less volume than liquid slurry.  Volume loss coupled with the interaction between partially set cement, borehole wall and casing cause a loss of hydrostatic pressure, leading to an underbalanced condition.  While the hydrostatic pressure in the partially set cement is below formation pressure, gas may invade.  If unchecked, the invasion of gas may create a channel through which gas can flow, effectively compromising cement quality and zonal isolation.  Also, cement damage can occur long after the well construction process.  Even a flawless primary cement job can be damaged by rig operations or well activities occurring after the cement has set.  Changing stresses in the wellbore may cause microannuli, stress cracks, or both, leading to SCP.  The mechanical properties of the casing and the cement vary significantly.  Consequently they do not behave in a uniform manner when exposed to changes in temperature and pressure.  As the casing and cement expand and contract, the bond between the cement sheath and casing may fail, causing microannulus, or flow path, to develop.

As the borehole reaches deeper into the earth, previously isolated layers of formation are exposed to one another, with the borehole as the conductive path.  Isolating these layers, or establishing zonal isolation, is key to minimizing the migration of formation fluids between zones or to the surface where SCP would develop.  Crucial to this process are borehole condition, effective mud removal, and cement-system design for placement, durability and adaptability to the well life cycle.  Wellbore condition depends on many factors, including rock type, formation pressures, local stresses, the type of mud used and drilling operation parameters, such as hydraulics, penetration rate, hole cleaning and fluid density balance.  The ultimate condition of the borehole is often determined early in the drilling process as drilling mud interacts with newly exposed formation.  If mismatched, the interaction of the drilling mud with formation clays can have serious detrimental effects on borehole gauge and rugosity.  Once a well is drilled, displacement, cementing and ultimately, zonal isolation efficiency are dependent on a stable borehole with minimal rugosity and tortuosity.  Drilling fluid engineers and related technical specialists have applied various techniques to investigate rock response to drilling fluid chemistry under simulated downhole conditions.  Mud companies have created high-performance water-base muds that incorporate various polymers, glycols, silicates and amines, or combination thereof, for clay control.  Like the fluids themselves, drilling fluid hydraulics play a fundamental role in constructing a quality borehole.  Balance must be maintained between fluid density, equivalent circulating density (ECD) and borehole cleaning.  If the static or dynamic fluid density is too high, loss of circulation may occur.  Conversely, if it is too low, shales and formation fluids may flow into the borehole, or in the worst case, well control may be lost.  Improper control of density and borehole hydraulics can lead to significant borehole rugosity, poor displacement and failure to achieve isolation.  Rheological properties of drilling fluids must be optimized in such a way that the frictional pressure losses are minimized without compromising cuttings-carrying capacity.  Optimal fluid properties for achieving good borehole cleaning and low frictional pressure loss often appear to be mutually exclusive.  Detailed engineering analysis is required to obtain an acceptable compromise that allows both objectives to be satisfied.  During drilling, optimal fluid characteristics may change depending on the task, such as running casing or displacement borehole fluids.  Modeling and simulation with software tools such as the M-I Virtual Hydraulics application can be useful in optimizing fluid properties in anticipation of changes in rig operations.  Integrating carefully designed drilling fluids with other key services is critical for achieving successful wellbore construction, zonal isolation and well integrity.

Proper mud selection and careful management of drilling practices generally produce a quality borehole that is near-gauge, stable and with minimal areas of rugosity, or washout.  To establish zonal isolation with cement, the drilling fluid must first be effectively removed from the borehole.  Mud removal depends on many interdependent factors.  Tubular geometry, downhole conditions, borehole characteristics, fluid rheology, displacement design, and hole geometry play major roles in successful mud removal.  Optimal fluid displacement requires a clear understanding of each variable as well as inherent interdependencies among variables.  The availability of computer technology has significantly advanced the way drillers approach wellbore displacement.  Fluids can be built, complex interactions predicted, and displacements simulated on the computer screen rather than at the wellsite where minor mistakes may result in major costs.  CemCADE cementing design and simulation software and WELLCLEAN II software are two software applications used for this purpose.

Integration of drilling fluids, spacer design and displacement techniques provide the foundation for optimal cement placement.  Long-term zonal isolation and control of gas require the cement to be properly placed and to provide low permeability, mechanical durability and adaptability to changing wellbore conditions.  Cement permeability depends on the solid fraction of the formulation.  For high-density slurries, a high solid fraction is inherent, thus the permeability tends to be low.  For low-density slurries, special products and techniques create low-density, high solid-fraction slurries.  Mechanical durability varies with strength, Young’s modulus of elasticity and Poisson’s ratio.  The cement should be designed so these properties are sufficient to prevent failure of the cement when exposed to changing well pressures and temperature fluctuations, which create stresses across the casing-cement-formation system.  Special materials are required to give the cement flexibility in this environment.    Sealing an annular space against gas migration can be more difficult in gas wells than in oil wells.  Wellbore construction, particularly in the presence of gas bearing formations, requires that borehole, drilling fluid, spacer and cement designs, and displacement techniques be dealt with as a series of interdependent systems, each playing an equally important role.  Often, the relationships among these systems is overlooked, or at the very least, poorly appreciated.  Preventing gas migration and SCP has been helped by recent developments in cementing technology that offer significant advantages in durability and adaptation to changing wellbore conditions.  Cement properties have traditionally been designed for optimal placement and strength development rather than long-term post-setting performance.  The rapid development of high cement-compressive strength after placement was generally considered adequate for most wellbore conditions.  Today, operators and service companies realize that the emphasis on strength at the expense of durability has often led to the development of SCP (sustained casing pressure) and reduced well productivity.  Cement particle characteristics and size distribution can contribute significantly to both the resistance to gas influx and maintenance of a sustainable hydraulic seal, particularly in wellbores subjected to pressure and temperature cycling.  FlexSTONE advanced flexible cement technology, part of the CemCRETE concrete-based oilwell cementing technology, is one of several solutions that effectively address cement flexibility and durability.  Conventional Portland cements are known to shrink during setting.  In contrast, FlexSTONE slurries can be designed to expand, further tightening the hydraulic seal and helping to compensate for variations in borehole or casing conditions.  This capability helps avoid microannuli development.  By adjusting specific additive characteristics and by blending the cement slurry with an engineered particle size distribution, a lowering of Young’s modulus of elasticity in cement can be achieved.  Annular cement can then flex in unison with the casing rather than failing from tensile stresses.  Thus, the potential development of microannuli and gas communication to the surface or to zones of lower pressure are minimized.”  The original complete version of the above paper can be found at

Issue 4:   DEC should not provide a well license to a person who does not furnish proof that the person has liability insurance of at least $5,000,000 per occurrence that provides compensation for all damages caused by drilling, pipeline construction, production, servicing or abandonment operations or caused by any vessel, craft or barge used to transport people or materials to the site of the drilling, pipeline construction or production operations.

I sincerely thank NYSDEC for welcoming the public’s comments on the dsGEIS and look forward to DEC’s response to my comments,

Jilda Rush

Attach:  email from Schlumberger dated 10/26/2008
British Columbia, Canada OGC Oil and Gas Commission Position Description

Cc: Gov. David Paterson, Top Advisor Judith Enck & Assemblyman Clifford Crouch

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MB writes:

I just attempted to call Grannis about this decision to do separate
reviews for NYC and Syracuse. I told the operator what my call was
about and I was transferred to the Division of Mineral Resources. I
asked them to please transfer me back to Grannis’s office. After I was
on hold for several minutes, someone answered my call and when I
explained that I was calling to register my displeasure at the plan to
give unequal treatment to different parts of the state, I was told
that they are not taking calls on this matter except through the
Division of Mineral Resources. She said that I could email my concerns
to Grannis, and then they would be documented. I told her I knew the
decision was not hers and I was not angry with her, but that I was
furious that the commissioner’s office is not taking calls on this
matter. I went ahead and told her that I was opposed to the unequal
treatment–she said she was keeping no record of the call. I told her
that I understood that, but I was telling her my position so that if
she got many, many similar calls, she could go and tell her superiors
that she had gotten a lot of calls in opposition to the unequal
treatment, even if the individual calls were not recorded. I also told
her that I have lived in and paid taxes in NY for over 25 years, and
that I bet if Chesapeake were to call about something they would get

People calling about Walter Hang’s effort to get the dSGEIS withdrawn
have been getting similar treatment.

We live in this state and they are not taking our calls! Are they
deliberately trying to piss us off or what? Do they think this will
make us LESS determined to stop this nightmare? If I sound furious,
that’s because I am.

If you have not already done so, please consider calling and sending
emails to the appropriate officials to express your displeasure at the
DEC’s recent decision to create separate regulations for the NYC and
Syracuse watersheds. Phone numbers and email addresses are:

DEC Commissioner Alexander “Pete” Grannis:

EPA Region 2 Administrator Judith Enck:

Governor David Paterson

When contacting Grannis and Paterson, you may also wish to complain
about the fact that, as of last Friday, Grannis’s office was NOT
accepting phone calls on this issue: they were instead transferring
the calls to our “friends” over in the Division of Mineral Resources.

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Last week, high-profile news stories indicated that “DEC won’t allow gas drilling in ‘the watershed.’”  Is that true?

You may have heard or read that the NYS Department of Environmental Conservation (DEC) has decided not to allow gas drilling within the Catskill and Delaware watersheds, which supply water to NYC.

Don’t believe it.

On April 23rd the DEC announced that it will exclude unfiltered water supplies from its generic environmental impact statement. Instead gas drilling applicants will have to go through their own environmental review process to obtain permits. [1] In the 1992 GEIS there are other situations which trigger an additional environmental review.

The main question is why did the DEC decide to release this statement now, instead of including it in the final Supplemental Generic Environmental Impact Statement (SGEIS)?

Here are three good reasons for this public relations stunt:

1. To diminish public opposition

Late last October, just before the start of the public review of the draft SGEIS, Aubrey K. McClendon, the head of Chesapeake Energy, announced that his company would not drill in the Catskill and Delaware watersheds. However, he was not willing to tear up their current leases, or sign a binding agreement never to drill there. Nor could he speak for the dozens of other gas drilling companies. The public saw through his maneuver and submitted over 14,000 comments to the draft.

It seems that Pete Grannis has been taking lessons from the CEO of Chesapeake Energy.

2. To try an end run around current proposed legislation

Over two dozen bills have been introduced in the NYS legislature about gas drilling. One that is gaining momentum calls for a state-wide moratorium until 120 days after the EPA finishes its report on hydrofracking. [2] Another proposed bill calls for a state-wide ban.

The last thing the DEC and the gas industry want is a multi-year moratorium. This press release is merely an attempt to stop these bills.

3. To try to avoid some legal requirements of their environmental review

NYS is in a very difficult position because no matter what they do they are going to get sued once the SGEIS is finalized. This move is an attempt to avoid some of those legal issues. However, it’s not likely to succeed since it simply creates a new legal challenge.

The point is this: gas drilling would still be allowed in unfiltered water supplies. The DEC’s decision does not block gas drilling anyplace, and it may not be legal.

[1]. DEC Press Release: DEC Announces Separate Review for Communities With “Filtration Avoidance Determinations”

[2]. Englebright bill, A10490

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